Management's Discussion and Analysis

Transcription

1 Management's Discussion and Analysis This Management's Discussion and Analysis ("MD&A") of the financial condition and performance of MEG Energy Corp. ("MEG" or the "Corporation") for the year ended December 31, 2017 was approved by the Board of Directors on March 8, This MD&A should be read in conjunction with the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2017 and its most recently filed Annual Information Form ( AIF ). This MD&A and the audited consolidated financial statements and comparative information have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ( IASB ) and are presented in thousands of Canadian dollars, except where otherwise indicated. MD&A Table of Contents 1. BUSINESS DESCRIPTION OPERATIONAL AND FINANCIAL HIGHLIGHTS RESULTS OF OPERATIONS OUTLOOK BUSINESS ENVIRONMENT OTHER OPERATING RESULTS NET CAPITAL INVESTMENT SUMMARY OF QUARTERLY RESULTS SUMMARY ANNUAL INFORMATION LIQUIDITY AND CAPITAL RESOURCES SHARES OUTSTANDING CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES SUBSEQUENT EVENTS NON-GAAP MEASURES CRITICAL ACCOUNTING POLICIES AND ESTIMATES TRANSACTIONS WITH RELATED PARTIES OFF-BALANCE SHEET ARRANGEMENTS NEW ACCOUNTING STANDARDS RISK FACTORS DISCLOSURE CONTROLS AND PROCEDURES INTERNAL CONTROLS OVER FINANCIAL REPORTING ABBREVIATIONS ADVISORY ADDITIONAL INFORMATION QUARTERLY SUMMARIES ANNUAL SUMMARIES

2 1. BUSINESS DESCRIPTION MEG is an oil sands company focused on sustainable in situ oil sands development and production in the southern Athabasca oil sands region of Alberta, Canada. MEG is actively developing enhanced oil recovery projects that utilize steam-assisted gravity drainage ( SAGD ) extraction methods. MEG is not engaged in oil sands mining. MEG owns a 100% working interest in over 900 square miles of oil sands leases. For information regarding MEG's estimated reserves contained in the GLJ Petroleum Consultants Ltd. Report ( GLJ Report ), please refer to the Corporation s most recently filed Annual Information Form ( AIF ), which is available on the Corporation s website at and is also available on the SEDAR website at The Corporation has identified three commercial SAGD projects: the Christina Lake Project, the Surmont Project and the May River Regional Project. The Christina Lake Project has received regulatory approval for 210,000 barrels per day ( bbls/d ) of bitumen production. MEG has applied for regulatory approval for 120,000 bbls/d of bitumen production at the Surmont Project. On February 21, 2017, MEG filed regulatory applications with the Alberta Energy Regulator for the May River Regional Project. Management anticipates, consistent with the estimates contained in the GLJ Report, that the May River Regional Project can support an average of 164,000 bbls/d of bitumen production. The ultimate production rate and life of each project will be dependent on a number of factors, including the size, performance and development schedule for each expansion or phase in those projects. In addition, the Corporation holds other leases known as the "Growth Properties. The Growth Properties are in the resource definition and data gathering stage of development. The Corporation's first two production phases at the Christina Lake Project, Phase 1 and Phase 2, commenced production in 2008 and 2009, respectively. In 2012, the Corporation announced the RISER initiative, which is a combination of proprietary reservoir technologies, including enhanced Modified Steam And Gas Push ( emsagp ) and redeployment of steam and facilities modifications, including debottlenecking and brownfield expansions (collectively RISER ). Phase 2B commenced production in Bitumen production at the Christina Lake Project for the year ended December 31, 2017 averaged 80,774 bbls/d. The application of emsagp and cogeneration have enabled MEG to lower its greenhouse gas intensity below the in situ industry average calculated based on reported data to Environment Canada, the Alberta Energy Regulator and the Alberta Electric System Operator. In those specific well patterns where the implementation of emsagp has already been deployed, the Corporation is currently experiencing a steam-oil ratio of approximately 1.3. MEG is currently continuing the process of implementing the RISER initiative, and specifically emsagp, to Phase 2B of the Christina Lake Project. The Surmont Project has an anticipated design capacity of approximately 120,000 bbls/d over multiple phases. The Surmont Project is located approximately 30 miles north of the Corporation s Christina Lake Project, and is situated along the same geological trend as the Christina Lake Project. The Corporation is actively pursuing regulatory approval. MEG currently holds a 100% interest in the Stonefell Terminal, located near Edmonton, Alberta, with a storage and terminalling capacity of 900,000 barrels. The Stonefell Terminal provides the Corporation with the ability to sell and deliver Access Western Blend ( AWB or blend ) opportunistically to a variety of markets, access multiple sources of diluent, and store both blend and diluent, including in periods of market and transportation disruptions or constraints. The Stonefell Terminal is directly connected by pipeline to a third party rail-loading terminal near Bruderheim, Alberta. This combination of facilities allows for the loading of bitumen blend for transport by rail. MEG currently holds a 50% interest in the Access Pipeline, a dual pipeline system that connects the Christina Lake Project to a large regional upgrading, refining, diluent supply and transportation hub in the Edmonton, Alberta area. The Corporation is taking a number of steps to address its financial leverage. In January 2017, MEG successfully completed a refinancing which pushed the first maturity of any of the Corporation s outstanding long-term debt obligations to The ongoing implementation of the emsagp growth project will increase future production 2

3 while further reducing MEG s per barrel costs, and strengthen the Corporation s ability to deal with the current volatility in crude oil prices. On February 8, 2018 the Corporation announced that it had entered into an agreement for the sale of the Corporation s 50% interest in the Access Pipeline and its 100% interest in the Stonefell Terminal for cash proceeds of C$1.52 billion and other consideration of C$90 million. Upon closing, a portion of the net cash proceeds will be used to repay approximately C$1.225 billion of MEG's senior secured term loan and to fund MEG s 13,000 bbls/d Phase 2B brownfield expansion. Closing of the transaction is anticipated to occur in the first quarter of As part of the transaction, MEG entered into a Transportation Services Agreement ( TSA ) dedicating MEG s Christina Lake production and condensate transport to Access Pipeline for an initial term of 30 years. The transaction also includes a Stonefell Lease Agreement which is a 30-year arrangement that secures MEG s operational control and exclusive use of 100% of the Stonefell Terminal s 900,000-barrel blend and condensate storage facility. In addition, the Corporation continues to consider, taking into account MEG s debt maturity profile and the ongoing price environment, other available options to reduce its overall amount of debt over time. 2. OPERATIONAL AND FINANCIAL HIGHLIGHTS During 2017, the Corporation continued to benefit from increases in its realized sales price. The average US$WTI price increased 18% in 2017 compared to Also, the average WCS differential narrowed by US$1.86 per barrel, or 13%, due to higher demand for Canadian heavy oil from U.S. Gulf Coast refineries. These factors were the primary drivers in the approximately C$14 per barrel increase in bitumen realization in 2017, as compared to Capital investment in 2017 totaled $502.8 million, an increase of $365.5 million compared to the same period of 2016, primarily as a result of increased investment in the emsagp growth project at Christina Lake Phase 2B. Total capital investment for 2017 approximated the Corporation s most recent guidance of $510 million. At December 31, 2017, the Corporation had cash and cash equivalents of $463.5 million and US$1.4 billion of undrawn capacity under the revolving credit facility. The Corporation continues to benefit from efficiency gains achieved through the continued implementation of emsagp at the Christina Lake project. Still in the first year of a two-year development plan, the emsagp growth project is proceeding as planned. The implementation of emsagp has improved reservoir efficiency and allowed for redeployment of steam, thereby enabling the Corporation to place additional wells into production. Exit bitumen production volumes for 2017 were 93,674 bbls/d. The Corporation s non-energy operating costs averaged $4.62 per barrel for 2017, an 18% decrease compared to $5.62 per barrel in The decrease in costs is a result of efficiency gains and continued cost management. The Corporation realized net earnings of $166.0 million for the year ended December 31, Net earnings are impacted by the foreign exchange rate as the Corporation s debt is denominated in U.S. dollars. The Canadian dollar strengthened overall in 2017, resulting in an unrealized foreign exchange gain of $338.1 million on a year-todate basis. On December 1, 2017, the Corporation announced a 2018 capital budget of $510 million. On February 8, 2018, following the announcement of the agreement for the sale of the Corporation s 50% interest in the Access Pipeline and its 100% interest in the Stonefell Terminal, the Corporation announced that it intends to increase its 2018 capital budget from $510 million to $700 million to fund approximately 70% of the Phase 2B brownfield expansion in The Corporation expects to fund the 2018 capital program with internally generated cash flow, a portion of its $463.5 million of cash and cash equivalents as at December 31, 2017 and a portion of the proceeds from the asset sales. 3

4 The Corporation s 2018 annual bitumen production volumes are targeted to be in the range of 85,000 88,000 bbls/d. Exit bitumen production for 2018 is targeted to be in the range of 95, ,000 bbls/day. Non-energy operating costs are targeted to be in the range of $4.75 $5.25 per barrel. The operational guidance takes into account a major turnaround at the Corporation s Christina Lake Phase 2B facility in 2018, with an anticipated 5,000 to 6,000 bbls/d impact on production for the year. The following table summarizes selected operational and financial information of the Corporation for the years noted. All dollar amounts are stated in Canadian dollars ($ or C$) unless otherwise noted: ($ millions, except as indicated) Bitumen production - bbls/d 80,774 81,245 Bitumen realization - $/bbl Net operating costs - $/bbl (1) Non-energy operating costs - $/bbl Cash operating netback - $/bbl (2) Adjusted funds flow from (used in) operations (3) 374 (62) Per share, diluted (3) 1.29 (0.27) Operating earnings (loss) (3) (114) (455) Per share, diluted (3) (0.39) (2.01) Revenue (4) 2,435 1,866 Net earnings (loss) 166 (429) Per share, basic 0.57 (1.90) Per share, diluted 0.57 (1.90) Total cash capital investment Cash and cash equivalents Long-term debt 4,668 5,053 (1) Net operating costs include energy and non-energy operating costs, reduced by power revenue. (2) Cash operating netback is calculated by deducting the related diluent expense, transportation, operating expenses, royalties and realized commodity risk management gains (losses) from proprietary blend revenues and power revenues, on a per barrel of bitumen sales volume basis. (3) Adjusted funds flow from (used in) operations, Operating earnings (loss) and the related per share amounts do not have standardized meanings prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. The non-gaap measure of adjusted funds flow from (used in) operations is reconciled to net cash provided by (used in) operating activities and the non-gaap measure of operating earnings (loss) is reconciled to net earnings (loss) in accordance with IFRS under the heading NON-GAAP MEASURES and discussed further in the ADVISORY section. (4) The total of Petroleum revenue, net of royalties and Other revenue as presented on the Consolidated Statement of Earnings and Comprehensive Income. 4

5 3. RESULTS OF OPERATIONS Bitumen Production and Steam-Oil Ratio Bitumen production bbls/d 80,774 81,245 Steam-oil ratio (SOR) Bitumen Production Bitumen production for the year ended December 31, 2017 averaged 80,774 bbls/d compared to 81,245 bbl/d for the year ended December 31, Average production for 2017 was affected by a planned 37-day turnaround at the Christina Lake Project, which was successfully completed in early June. The 2017 turnaround had a greater impact on production volumes compared to only minor capital activities during the same period in Steam-Oil Ratio SOR is an important efficiency cy indicator that measures the average amount of steam that is injected into the reservoir for each barrel of bitumen produced. The Corporation continues to focus on maintaining efficiency of production through a lower SOR. The SOR averaged 2.3 for the years ended December 31, 2017 and Operating Cash Flow ($000) Petroleum revenue proprietary (1) $ 2,168,602 $ 1,626,025 Diluent expense (944,134) (808,030) 1,224, ,995 Royalties (22,578) (8,581) Transportation expense (214,280) (209,864) Operating expenses (222,196) (253,758) Power revenue 22,209 18,868 Transportation revenue 12,801 19, , ,451 Realized gain (loss) on commodity risk management (11,273) 2,359 Operating cash flow (2) $ 789,151 $ 386,810 (1) Proprietary petroleum revenue represents MEG's revenue ( blend sales revenue ) from its heavy crude oil blend known as Access Western Blend ("AWB or blend ). Blend is comprised of bitumen produced at the Christina Lake Project blended with purchased diluent. (2) A non-gaap measure as defined in the NON-GAAP MEASURES section of this MD&A. Operating cash flow was $789.2 million for the year ended December 31, 2017 compared to $386.8 million for the year ended December 31, The 104% increase is primarily due to higher blend sales revenue as a result of the increase in average crude oil benchmark pricing, partially offset by an increase in diluent expense. The increase in blend sales revenue is primarily due to a 35% increase in the average realized blend price. Diluent expense for the year ended December 31, 2017 was $136.1 million higher than the year ended December 31, 2016, primarily due to an increase in condensate prices. 5

6 Cash Operating Netback 30.0 $14.10 $(0.43) $1.00 $0.03 $0.12 $(0.48) $(0.47) 25.0 $ $/bbl $ (5.0) 2016 Bitumen realization Transportation Royalties Operating costs - non-energy Operating costs - energy Power revenue Realized risk management 2017 The following table summarizes the Corporation s per-unit calculation of operating cash flow, defined as cash operating netback for the years indicated: ($/bbl) Bitumen realization (1) $ $ Transportation (2) (6.89) (6.46) Royalties (0.77) (0.29) Operating costs non-energy (4.62) (5.62) Operating costs energy (2.98) (3.01) Power revenue Net operating costs (6.84) (7.99) Realized gain (loss) on commodity risk management (0.39) 0.08 Cash operating netback $ $ (1) Blend sales revenue net of diluent expense. (2) Defined as transportation expense less transportation revenue. Transportation includes rail, third-party pipelines and the Stonefell Terminal costs, as well as MEG s share of the operating costs for the Access Pipeline, net of third-party recoveries on diluent transportation arrangements. Bitumen Realization Bitumen realization represents the Corporation's realized proprietary petroleum revenue ( blend sales revenue ), net of diluent expense, expressed on a per barrel basis. Blend sales revenue represents MEG s revenue from its heavy crude oil blend known as Access Western Blend ("AWB or blend ). AWB is comprised of bitumen produced at the Christina Lake Project blended with purchased diluent. The cost of blending is impacted by the amount of 6

7 diluent required and the Corporation s cost of purchasing and transporting diluent. A portion of diluent expense is effectively recovered in the sales price of the blended product. Diluent expense is also impacted by Canadian and U.S. benchmark pricing, the timing of diluent inventory purchases and changes in the value of the Canadian dollar relative to the U.S. dollar. Bitumen realization averaged $41.89 per barrel for the year ended December 31, 2017 compared to $27.79 per barrel for the year ended December 31, The increase in bitumen realization is primarily a result of the increase in average crude oil benchmark pricing, which resulted in higher blend sales revenue. For the year ended December 31, 2017, the Corporation s cost of diluent was $72.32 per barrel of diluent compared to $61.06 per barrel of diluent for the year ended December 31, The increase in the cost of diluent is primarily a result of the increase in average condensate benchmark pricing. Transportation The Corporation utilizes multiple facilities to transport and sell its blend to refiners throughout North America. In early 2016, the Corporation increased its transportation capacity on the Flanagan South and Seaway pipeline systems, thereby furthering the Corporation s strategy of broadening market access to world prices with the intention of improving cash operating netback. Sales volumes destined for U.S. markets require additional transportation costs, but generally obtain higher sales prices. As a result of a higher proportion of blend sales volumes shipped from Edmonton to the U.S. Gulf Coast via the Flanagan South and Seaway pipeline systems during the year ended December 31, 2017, transportation costs averaged $6.89 per barrel for the year ended December 31, 2017 compared to $6.46 per barrel for the year ended December 31, Royalties The Corporation's royalty expense is based on price-sensitive royalty rates set by the Government of Alberta. The applicable royalty rates change depending on whether a project is pre-payout or post-payout, with payout being defined as the point in time when a project has generated enough cumulative net revenues to recover its cumulative costs. The royalty rate applicable to pre-payout oil sands operations starts at 1% of bitumen sales and increases for every dollar that the WTI crude oil price in Canadian dollars is priced above $55 per barrel, to a maximum of 9% when the WTI crude oil price is $120 per barrel or higher. All of the Corporation's projects are currently pre-payout. The increase in royalties for the year ended December 31, 2017, compared to the year ended December 31, 2016 is primarily the result of higher realized WTI crude oil prices. Net Operating Costs Net operating costs are comprised of the sum of non-energy operating costs and energy operating costs, reduced by power revenue. Non-energy operating costs represent production-related operating activities. Energy operating costs represent the cost of natural gas for the production of steam and power at the Corporation s facilities. Power revenue is the sale of surplus power generated by the Corporation s cogeneration facilities at the Christina Lake Project. Net operating costs for the year ended December 31, 2017 averaged $6.84 per barrel compared to $7.99 per barrel for the year ended December 31, The decrease in net operating costs is primarily the result of a per barrel decrease in non-energy operating costs. 7

8 Non-energy operating costs Non-energy operating costs averaged $4.62 per barrel for the year ended December 31, 2017 compared to $5.62 per barrel for the year ended December 31, The decrease in non-energy operating costs is primarily the result of efficiency gains and a continued focus on cost management resulting in lower operations staffing and materials and services costs, plus a $0.15 per barrel, or $4.5 million reduction of property taxes related to a onetime municipal reassessment of its Christina Lake facility in the second quarter of Energy operating costs Energy operating costs averaged $2.98 per barrel for the year ended December 31, 2017 which were substantially consistent with $3.01 per barrel for the year ended December, The Corporation s natural gas purchase price averaged $2.59 per mcf during the year ended December 31, 2017 compared to $2.53 per mcf for the same period in Power revenue Power revenue averaged $0.76 per barrel for the year ended December 31, 2017 compared to $0.64 per barrel for the year ended December 31, The Corporation s average realized power sales price during the year ended December 31, 2017 was $21.49 per megawatt hour compared to $18.74 per megawatt hour for the same period in Adjusted Funds Flow From (Used In) Operations Year Ended December $406.5 $(14.0) $(11.4) $34.9 $(2.7) $9.5 $12.6 $ $ millions (50.0) $(61.6) (100.0) 2016 Bitumen realization (1) Royalties (2) (3) (4) Transportation Net operating Interest, net costs General & administrative Other 2017 (1) Net of diluent expense. (2) Defined as transportation expense less transportation revenue. (3) Includes non-energy and energy operating costs, reduced by power revenue. (4) Defined as total interest expense plus realized gain/loss on interest rate swaps less amortization of debt discount and debt issue costs. 8

9 Adjusted funds flow from (used in) operations is a non-gaap measure, as defined in the NON-GAAP MEASURES section of this MD&A, which is used by the Corporation to analyze operating performance and liquidity. Adjusted funds flow from operations was $373.8 million for the year ended December 31, 2017 compared to adjusted funds flow used in operations of $(61.6) million for the year ended December 31, The increase was primarily due to an increase in bitumen realization, as a result of the increase in average crude oil benchmark pricing. Operating Earnings (Loss) Operating earnings (loss) is a non-gaap measure, as defined in the NON-GAAP MEASURES section of this MD&A, which the Corporation uses as a performance measure to provide comparability of financial performance between periods by excluding non-operating items. The Corporation recognized an operating loss of $113.5 million for the year ended December 31, 2017 compared to an operating loss of $455.1 million for the year ended December 31, The decrease in the operating loss was primarily due to higher bitumen realization as a result of the increase in average crude oil benchmark pricing. Revenue Revenue represents the total of petroleum revenue, net of royalties and other revenue. Revenue for the year ended December 31, 2017 totaled $2.43 billion compared to $1.87 billion for the year ended December 31, Revenue increased primarily due to an increase in blend sales revenue as a result of the increase in average crude oil benchmark pricing. Net Earnings (Loss) The Corporation recognized net earnings of $166.0 million for the year ended December 31, 2017 compared to a net loss of $428.7 million for the year ended December 31, In addition to the impact of higher average crude oil benchmark pricing in 2017 as previously discussed under cash operating netback, the net unrealized foreign exchange gain increased by $190.0 million in 2017 compared to Also in 2016, the Corporation recognized an $80.1 million impairment charge related to the Northern Gateway pipeline. Total Cash Capital Investment Total cash capital investment during the year ended December 31, 2017 totaled $502.8 million as compared to $137.2 million for the year ended December 31, Capital investment in 2017 has been primarily directed towards the Corporation s emsagp production growth initiative at Christina Lake Phase 2B and sustaining capital activities. 4. OUTLOOK Summary of 2017 Guidance Guidance October 26, 2017 Annual Results Capital investment $510 million $503 million Bitumen production annual average (bbls/d) 80,000 82,000 80,774 Bitumen production targeted exit volume (bbls/d) 86,000 89,000 93,674 Non-energy operating costs ($/bbl) $4.75 $5.00 $4.62 Capital investment for 2017 was $503 million, which approximated the Corporation s most recent 2017 capital investment guidance of $510 million issued on October 26, Annual bitumen production averaged 80,774 bbls/d, consistent with the Corporation s most recent 2017 production guidance. 9

10 As a result of the continued implementation of emsagp, exit bitumen production volumes were 93,674 bbls/d, which exceeded the Corporation s most recent 2017 exit production guidance. As a result of efficiency gains and a continued focus on cost management, annual non-energy operating costs averaged $4.62 per barrel, representing a 5% reduction from the mid-point of the most recent 2017 guidance. Summary of 2018 Guidance Capital investment $700 million Bitumen production annual average (bbls/d) 85,000 88,000 Bitumen production targeted exit volume (bbls/d) 95, ,000 Non-energy operating costs ($/bbl) $4.75 $5.25 On December 1, 2017, the Corporation announced a 2018 capital budget of $510 million. On February 8, 2018, following the announcement of the agreement for the sale of the Corporation s 50% interest in the Access Pipeline and its 100% interest in the Stonefell Terminal, the Corporation announced it intends to increase its 2018 capital budget from $510 million to $700 million to fund approximately 70% of the Phase 2B brownfield expansion in The Corporation expects to fund the 2018 capital program with internally generated cash flow, a portion of its $463.5 million of cash and cash equivalents as at December 31, 2017 and a portion of the proceeds from the asset sales. The Corporation s 2018 annual bitumen production volumes are targeted to be in the range of 85,000 88,000 bbls/d. Exit bitumen production for 2018 is targeted to be in the range of 95, ,000 bbls/day. Non-energy operating costs are targeted to be in the range of $4.75 $5.25 per barrel. The operational guidance takes into account a major turnaround at the Corporation s Christina Lake Phase 2B facility in 2018, with an anticipated 5,000 to 6,000 bbls/d impact on production for the year. 10

11 5. BUSINESS ENVIRONMENT The following table shows industry commodity pricing information and foreign exchange rates on a quarterly and annual basis to assist in understanding the impact of commodity prices and foreign exchange rates on the Corporation s financial results: Average Commodity Prices Crude oil prices Year ended December Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Brent (US$/bbl) WTI (US$/bbl) WTI (C$/bbl) WCS (C$/bbl) Differential WTI:WCS (US$/bbl) Differential WTI:WCS (%) 23.5% 31.9% 22.1% 20.6% 23.0% 28.1% 29.1% 30.0% 29.2% 42.6% Condensate prices Condensate at Edmonton (C$/bbl) Condensate at Edmonton as % of WTI 101.2% 97.9% 104.6% 98.7% 100.3% 100.7% 98.1% 95.9% 96.7% 102.8% Condensate at Mont Belvieu, Texas (US$/bbl) Condensate at Mont Belvieu, Texas as % of WTI 94.5% 91.6% 99.9% 96.2% 92.7% 88.7% 91.6% 91.6% 88.6% 95.8% Natural gas prices AECO (C$/mcf) Electric power prices Alberta power pool (C$/MWh) Foreign exchange rates C$ equivalent of 1 US$ - average C$ equivalent of 1 US$ - period end Crude Oil Prices Brent crude is the primary world price benchmark for global light sweet crude oil. The price of WTI is the current benchmark for mid-continent North American crude oil prices, at Cushing Oklahoma, and its Canadian dollar equivalent is the basis for determining the royalty rate on the Corporation's bitumen sales. The WTI price averaged US$50.95 per barrel for the year ended December 31, 2017 compared to US$43.33 per barrel for the year ended December 31, WCS is a blend of heavy oils, consisting of heavy conventional crude oils and bitumen, blended with sweet synthetic, light crude oil or condensate. The WCS benchmark reflects North American prices at Hardisty, Alberta. WCS typically trades at a differential below the WTI benchmark price. The WTI:WCS differential averaged US$11.98 per barrel, or 23.5% of WTI, for the year ended December 31, 2017 compared to US$13.84 per barrel, or 31.9% of WTI, for the year ended December 31, Condensate Prices In order to facilitate pipeline transportation, MEG uses condensate sourced throughout North America as diluent for blending with the Corporation s bitumen. Condensate prices, benchmarked at Edmonton, averaged $66.91 per barrel, or 101.2% of WTI, for the year ended December 31, 2017 compared to $56.21 per barrel, or 97.9% of WTI, for the year ended December 31,

12 Condensate prices, benchmarked at Mont Belvieu, Texas, averaged US$48.14 per barrel, or 94.5% of WTI, for the year ended December 31, 2017 compared to US$39.68 per barrel, or 91.6% of WTI, for the year ended December 31, Natural Gas Prices Natural gas is a primary energy input cost for the Corporation, as it is used as fuel to generate steam for the SAGD process and to create electricity from the Corporation's cogeneration facilities. The AECO natural gas price averaged $2.29 per mcf for the year ended December 31, 2017 compared to $2.25 per mcf for the year ended December 31, Electric Power Prices Electric power prices impact the price that the Corporation receives on the sale of surplus power from the Corporation s cogeneration facilities. The Alberta power pool price averaged $22.17 per megawatt hour for the year ended December 31, 2017 compared to $18.19 per megawatt hour for the year ended December 31, Foreign Exchange Rates Changes in the value of the Canadian dollar relative to the U.S. dollar have an impact on the Corporation's blend sales revenue and diluent expense, as blend sales prices and diluent expense are determined by reference to U.S. benchmarks. Changes in the value of the Canadian dollar relative to the U.S. dollar also have an impact on principal and interest payments on the Corporation's U.S. dollar denominated debt. A decrease in the value of the Canadian dollar compared to the U.S. dollar has a positive impact on blend sales revenue and a negative impact on diluent expense and principal and interest payments. Conversely, an increase in the value of the Canadian dollar has a negative impact on blend sales revenue and a positive impact on diluent expense and principal and interest payments. The Corporation recognizes net unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated debt and U.S. dollar denominated cash and cash equivalents at each reporting date. As at December 31, 2017, the Canadian dollar, at a rate of , had increased in value by approximately 7% against the U.S. dollar compared to its value as at December 31, 2016, when the rate was OTHER OPERATING RESULTS Net Marketing Activity ($000) Petroleum revenue third party $ 253,486 $ 205,790 Purchased product and storage (250,681) (202,135) Net marketing activity (1) $ 2,805 $ 3,655 (1) Net marketing activity is a non-gaap measure as defined in the NON-GAAP MEASURES section. The Corporation has entered into marketing arrangements for rail and pipeline transportation commitments and product storage arrangements to enhance its ability to transport proprietary crude oil products to a wider range of markets in Canada, the United States and on tidewater. In the event that the Corporation is not utilizing these arrangements for proprietary purposes, the Corporation purchases and sells third-party crude oil and related products and enters into transactions to generate revenues to offset the costs of such marketing and storage arrangements. 12

13 Depletion and Depreciation ($000) Depletion and depreciation expense $ 475,644 $ 499,811 Depletion and depreciation expense per barrel of production $ $ Depletion and depreciation expense decreased, primarily due to a significant reduction in estimated future development costs associated with the Corporation s proved reserves. Future development costs are derived from the Corporation s independent reserve report and are a key element of the rate determination. The decrease in future development costs is primarily related to the Corporation s future growth strategy, which anticipates reduced capital requirements to produce the reserves. Impairment There were no impairments recognized in At December 31, 2016, the Corporation evaluated its investment in the right to participate in the Northern Gateway pipeline for impairment, in relation to the December 6, 2016 directive from the Government of Canada to the National Energy Board ( NEB ) to dismiss the project application. As a result, the Corporation fully impaired its investment and recognized a fourth quarter 2016 impairment charge of $80.1 million. Commodity Risk Management Gain (Loss) The Corporation has entered into financial commodity risk management contracts. The Corporation has not designated any of its commodity risk management contracts as hedges for accounting purposes. All financial commodity risk management contracts have been recorded at fair value, with all changes in fair value recognized through net earnings (loss). Realized gains or losses on financial commodity risk management contracts are the result of contract settlements during the year. Unrealized gains or losses on financial commodity risk management contracts represent the change in the mark-to-market position of the unsettled commodity risk management contracts during the year. ($000) Realized Unrealized Total Realized Unrealized Total Crude oil contracts (1) $ (53,364) $ (9,245) $ (62,609) $ (9,888) $ (59,404) $ (69,292) Condensate contracts (2) 42,091 (29,091) 13,000 12,247 29,091 41,338 Commodity risk management gain (loss) $ (11,273) $ (38,336) $ (49,609) $ 2,359 $ (30,313) $ (27,954) (1) Includes WTI fixed price, WTI collars and WCS fixed differential contracts. (2) Relates to condensate purchase contracts that effectively fix condensate prices at Mont Belvieu, Texas as a percentage of WTI (US$/bbl). The Corporation realized a net loss on commodity risk management contracts of $11.3 million for the year ended December 31, 2017, primarily due to net settlement losses on contracts relating to crude oil sales, partially offset by settlement gains on condensate purchase contracts. This compares to a realized net gain of $2.4 million for the year ended December 31, The Corporation recognized an unrealized loss on commodity risk management contracts of $38.3 million for the year ended December 31, 2017, reflecting unrealized losses on condensate purchase contracts and crude oil contracts. Crude oil benchmark forward prices increased over the period, resulting in unrealized losses on the Corporation s WTI fixed price contracts and collars. This was partially offset by unrealized gains on WCS fixed differential contracts, due to a widening of WCS forward differentials. The $38.3 million unrealized loss in

14 compares to a $30.3 million unrealized loss in Refer to the Risk Management section of this MD&A for further details. General and Administrative ($000) General and administrative expense $ 86,785 $ 96,241 General and administrative expense per barrel of production $ 2.94 $ 3.24 General and administrative expense decreased primarily due to workforce reductions and the Corporation s continued focus on cost management. Stock-based Compensation ($000) Cash-settled expense $ 3,476 $ 16,354 Equity-settled expense 19,052 33,588 Stock-based compensation $ 22,528 $ 49,942 The fair value of compensation associated with the granting of stock options, restricted share units ("RSUs"), performance share units ("PSUs") and deferred share units ( DSUs ) to officers, directors, employees and consultants is recognized by the Corporation as stock-based compensation expense. Fair values for equity-settled plans are determined using the Black-Scholes option pricing model. The Corporation also grants RSUs, PSUs and DSUs under cash-settled plans. RSUs generally vest over a three year period while PSUs generally vest on the third anniversary of the grant date, provided that the Corporation satisfies certain performance criteria identified by the Corporation s Board of Directors within a target range. Upon vesting of the RSUs and PSUs, the participants of the cash-settled RSU plan will receive a cash payment based on the fair value of the underlying share units at the vesting date. The cash-settled RSUs, PSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of the Corporation s common shares at each period end. Fluctuations in the fair value are recognized within stock-based compensation expense or capitalized to property, plant and equipment during the period in which they occur. Stock-based compensation expense for the year ended December 31, 2017 was $22.5 million compared to $49.9 million for the year ended December 31, The decrease is primarily due to a decrease in the fair value of cashsettled units due to the decrease in the Corporation s common share price during 2017 in combination with a decrease in equity-settled share-based compensation expense. The Corporation commenced issuing RSUs and PSUs under a cash-settled plan in Research and Development Year ended December 31 ($000) Research and development expense $ 5,808 $ 5,499 Research and development expenditures relate to the Corporation's research of crude quality improvement and related technologies. 14

15 Foreign Exchange Gain (Loss), Net ($000) Unrealized foreign exchange gain (loss) on: Long-term debt $ 343,633 $ 157,272 Other (5,489) (9,119) Unrealized net gain (loss) on foreign exchange 338, ,153 Realized gain (loss) on foreign exchange 4,403 3,242 Foreign exchange gain (loss), net $ 342,547 $ 151,395 C$ equivalent of 1 US$ Beginning of year End of year The net foreign exchange gains and losses are primarily due to the translation of the U.S. dollar denominated debt as a result of the strengthening or weakening of the Canadian dollar compared to the U.S. dollar during each period. For the years ended December 31, 2017 and 2016, the Canadian dollar strengthened by 7% and 3%, respectively. This resulted in a net foreign exchange gain of $342.5 million in 2017 compared to a net foreign exchange gain of $151.4 million in Net Finance Expense ($000) Total interest expense $ 341,594 $ 328,335 Total interest income (3,924) (1,047) Net Interest expense 337, ,288 Debt extinguishment expense 30,801 28,845 Accretion on provisions 7,760 7,150 Unrealized loss (gain) on derivative financial liabilities (1) (16,179) (12,508) Realized loss on interest rate swaps 1,028 4,548 Net finance expense $ 361,080 $ 355,323 Average effective interest rate (2) 6.1% 5.8% (1) Derivative financial liabilities include the 1% interest rate floor and interest rate swaps. (2) Defined as the weighted average interest rate applied to the U.S. dollar denominated senior secured term loan, Senior Secured Second Lien Notes, and Senior Unsecured Notes outstanding, including the impact of interest rate swaps. Total interest expense for the year ended December 31, 2017 was $341.6 million compared to $328.3 million for the year ended December 31, This increase was due to higher effective interest rates and the incremental interest expense associated with carrying both the now repaid US$750 million aggregate principal amount of 6.5% Senior Unsecured Notes and the new 6.5% Senior Secured Second Lien Notes for a period of 49 days during the first quarter of Given the reduction in the early redemption premium threshold between closing and March 15, 2017, the economic cost of carrying interest on these notes for an incremental 49 days was less than the cost of redeeming the notes prior to March 15, The 6.5% Senior Unsecured Notes were repaid on March 15, 2017 with the proceeds from the Senior Secured Second Lien Notes. This issuance and repayment of notes was part of 15

16 the Corporation s comprehensive refinancing plan which is further described in the LIQUIDITY AND CAPITAL RESOURCES section of this MD&A. On February 8, 2018, the Corporation announced that it had entered into an agreement for the sale of the Corporation s 50% interest in the Access Pipeline and its 100% interest in the Stonefell Terminal, as described in the SUBSEQUENT EVENTS section of this MD&A. Upon closing, a portion of the net cash proceeds will be used to repay approximately C$1.225 billion of the Corporation s senior secured term loan. The expected repayment of debt reduces the estimated amortization period of the unamortized debt discount and debt issue costs, and the unamortized financial derivative liability discount. The change in estimate is an adjusting subsequent event under IAS 10, Events after the Reporting Period, and a debt extinguishment expense of $30.8 million was recorded at December 31, The debt extinguishment expense is comprised of the unamortized proportion of the senior secured term loan debt discount and debt issue costs of $17.0 million and the unamortized proportion of the senior secured term loan financial derivative liability discount of $13.8 million. At December 31, 2016, the Corporation recognized $28.8 million of debt extinguishment expense associated with the planned redemption of the 6.5% Senior Unsecured Notes on March 15, 2017, under the comprehensive refinancing plan completed on January 27, 2017, as described in the LIQUIDITY AND CAPITAL RESOURCES section of this MD&A. Unrealized gains and losses on derivative liabilities include changes in fair value of both the interest rate floor associated with the Corporation's senior secured term loan and the interest rate swap contracts. The Corporation recognized an unrealized gain on derivative financial liabilities of $16.2 million for the year ended December 31, 2017 compared to an unrealized gain of $12.5 million for the year ended December 31, In the third quarter of 2017, the Corporation entered into an interest rate swap contract to effectively fix the interest rate on US$650.0 million of its US$1.2 billion senior secured term loan at approximately 5.3%. This interest rate swap contract commenced September 29, 2017 and expires on December 31, The Corporation realized a loss on the interest rate swaps of $1.0 million for the year ended December 31, In 2016, the Corporation realized a loss on interest rate swaps of $4.5 million. These swap contracts effectively fixed the interest rate on US$748.0 million of its US$1.2 billion senior secured term loan and expired on September 30, Other Expenses ($000) Contract cancellation expense $ 18,765 $ - Onerous contracts 10,830 47,866 Severance and other 5,131 16,156 Other expenses $ 34,726 $ 64,022 During the third quarter of 2017, the Corporation recognized contract cancellation expense of $18.8 million relating to the termination of a long-term transportation contract. Onerous contracts expense primarily includes changes in estimated future sublease recoveries related to the onerous contracts provision for the Corporation s office building leases. 16

17 Income Tax Expense (Recovery) ($000) Current income tax expense (recovery) $ (67) $ 919 Deferred income tax expense (recovery) (56,130) (208,413) Income tax expense (recovery) $ (56,197) $ (207,494) The Corporation recognizes current income taxes associated with its operations in the United States. The Corporation s Canadian operations are not currently taxable. As at December 31, 2017, the Corporation had approximately $8.4 billion of available Canadian tax pools. The Corporation recognized a current income tax recovery of $0.1 million and an expense of $0.9 million in the years ended December 31, 2017 and 2016, respectively. The 2017 recovery is comprised of $0.8 million related to the refundable Alberta tax credit on Scientific Research and Experimental Development expenditures, partially offset by an expense of $0.7 million related to the United States income tax associated with its operations in the United States. The 2016 expense was related to the United States income tax associated with its operations in the United States. The Corporation recognized a deferred income tax recovery of $56.1 million for the year ended December 31, 2017 and a deferred income tax recovery of $208.4 million for the year ended December 31, The Corporation's effective tax rate on earnings is impacted by permanent differences. The significant permanent differences are: The permanent difference due to the non-taxable portion of realized and unrealized foreign exchange gains and losses arising on the translation of the U.S. dollar denominated debt. For the year ended December 31, 2017, the non-taxable net gain was $171.9 million compared to a non-taxable gain of $78.6 million for the year ended December 31, Non-taxable stock-based compensation expense for equity-settled plans is a permanent difference. Stockbased compensation expense for equity-settled plans for the year ended December 31, 2017 was $19.1 million compared to $33.6 million for the year ended December 31, As at December 31, 2017, the Corporation has recognized a deferred income tax asset of $182.9 million on the Consolidated Balance Sheet, as estimated future taxable income is expected to be sufficient to realize the deferred income tax asset. As at December 31, 2017, the Corporation had not recognized the tax benefit related to $445.7 million of realized and unrealized taxable foreign exchange losses. 17

18 7. NET CAPITAL INVESTMENT ($000) emsagp growth $ 222,982 $ 2,678 Sustaining 189,288 64,230 Marketing, corporate and other 90,484 70,337 Total cash capital investment 502, ,245 Capitalized cash-settled stock-based compensation (308) 2,491 $ 502,446 $ 139,736 Total cash capital investment for the year ended December 31, 2017 was $502.8 million as compared to $137.2 million for the year ended December 31, During 2017, the Corporation invested $223.0 million in the first year of its two-year development plan for the emsagp growth project at Christina Lake Phase 2B. Also in 2017, the Corporation invested $189.3 million in sustaining capital activities, including turnaround costs of $37.1 million incurred in the second quarter. In 2016, the Corporation was focused on reducing capital spending and capital investments were primarily directed towards sustaining capital activities. 18

19 8. SUMMARY OF QUARTERLY RESULTS The following table summarizes selected financial information for the Corporation for the preceding eight quarters: ($ millions, except per share amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Revenue (1) $754.8 $546.1 $574.0 $559.8 $565.8 $496.8 $513.4 $290.3 Net earnings (loss) (23.8) (304.8) (108.6) (146.2) Per share basic (0.08) (1.34) (0.48) (0.65) 0.58 Per share diluted (0.08) (1.34) (0.48) (0.65) 0.58 (1) The total of Petroleum revenue, net of royalties and Other revenue as presented on the Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss). During the eight most recent quarters the following items have had a significant impact on the Corporation s quarterly results: fluctuations in blend sales pricing due to significant changes in the price of WTI and the differential between WTI and the Corporation's AWB; the cost of diluent due to Canadian and U.S. benchmark pricing and the timing of diluent inventory purchases; changes in the value of the Canadian dollar relative to the U.S. dollar and its impact on blend sales prices, the cost of diluent, interest expense, and foreign exchange gains and losses associated with the Corporation's U.S. dollar denominated debt; increased bitumen production volumes due to efficiency gains achieved through the continued implementation of emsagp at the Christina Lake Project, which has allowed additional wells to be placed into production; fluctuations in natural gas and power pricing; gains and losses on commodity risk management contracts; other expenses primarily related to contract cancellation expense, onerous contracts and severance costs; a fourth quarter 2016 impairment charge related to the Corporation s investment in the right to participate in the Northern Gateway pipeline; and changes in depletion and depreciation expense as a result of changes in production rates and future development costs. 19